U.S. patent application number 10/071279 was filed with the patent office on 2002-10-03 for tubing elongation correction system & methods.
Invention is credited to Rios-Aleman, David E., Song, Haoshi.
Application Number | 20020139527 10/071279 |
Document ID | / |
Family ID | 26752050 |
Filed Date | 2002-10-03 |
United States Patent
Application |
20020139527 |
Kind Code |
A1 |
Song, Haoshi ; et
al. |
October 3, 2002 |
TUBING ELONGATION CORRECTION SYSTEM & METHODS
Abstract
A surface processor uses an environmental profile to determine
the sub-surface length of tubing disposed in a well bore.
Information relating to tubing properties is stored in a memory
module of the surface processor. The environmental profile includes
data relating to well bore ambient conditions and the operating
parameters of well equipment. Surface processor calculates the
tubing elongation or length reduction corresponding to the
environmental profile. Surface processor may repeat this process to
develop a measured depth chart for a well. Logging operations
performed in conjunction with the sub-surface length calculations
allows formation data to be associated with the measured depth
chart.
Inventors: |
Song, Haoshi; (Sugar Land,
TX) ; Rios-Aleman, David E.; (Houston, TX) |
Correspondence
Address: |
CONLEY ROSE & TAYON, P.C.
P. O. BOX 3267
HOUSTON
TX
77253-3267
US
|
Family ID: |
26752050 |
Appl. No.: |
10/071279 |
Filed: |
February 8, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60269280 |
Feb 16, 2001 |
|
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|
Current U.S.
Class: |
166/255.1 ;
166/66 |
Current CPC
Class: |
E21B 47/04 20130101;
G01B 5/0011 20130101; E21B 47/022 20130101 |
Class at
Publication: |
166/255.1 ;
166/66 |
International
Class: |
E21B 047/09 |
Claims
What is claimed is:
1. A method of determining a sub-surface length of tubing injected
into a borehole wherein the method comprises: (a) recording a
surface-measured length of the tubing prior to injection; (b)
determining an environmental profile; and (c) calculating the
sub-surface tubing length by correcting the surface-measured tubing
length to account for the environmental profile.
2. The method of claim 1 wherein the environmental profile of step
(b) includes at least surface and sub-surface temperature data.
3. The method of claim 1 wherein the environmental profile of step
(b) includes at least drilling fluid pressure data.
4. The method of claim 1 wherein the environmental profile of step
(b) includes at least drilling fluid hydraulic flow data.
5. The method of claim 1 wherein the environmental profile of step
(b) includes at least one tension force applied to the tubing.
6. The method of claim 5 wherein step (c) is accomplished by first
determining the tension in the tubing and then determining the
change in length due to the tension in the tubing.
7. For tubing made of material that deforms when exposed to a well
bore environment, a method of determining a sub-surface length of
tubing injected into a borehole, comprising: (a) recording a
surface-measured length of the tubing prior to injection; (b)
determining an environmental profile that includes a surface
temperature, a well bore temperature, a hydraulic pressure and flow
data for drilling fluid flowing inside the tubing, a hydraulic
pressure and flow data for drilling fluid flowing outside the
tubing, a tension in the tubing, and frictional forces acting on
the tubing; (c) calculating a first length change using the surface
temperature, the well bore temperature, and a coefficient of
thermal expansion for the tubing material at the well bore
temperature; (d) calculating a second length change using the
hydraulic pressure of drilling fluid flowing inside the tubing, the
hydraulic pressure of drilling fluid flowing outside the tubing,
and a Poisson's Ratio and Modulus of Elasticity for the tubing
material at the well bore temperature; (e) calculating a third
length change using the tension in the tubing, the surface tension,
and the frictional forces acting on the tubing; and (f)
establishing the sub-surface tubing length using the first, second
and third length change.
8. A well construction system, comprising: a tubing string having a
terminal end; a sensor package mounted proximate to said terminal
end of said tubing string, said sensor package configured to detect
well bore environmental data; a tubing length measurement counter
associated with said tubing string; a plurality of sensors on the
surface, said surface sensors configured to detect surface
environmental data; a surface processor configured to receive said
well bore and surface environmental data, and a first module
associated with said surface processor, said first module
configured to calculate a sub-surface tubing length based on said
wellbore and surface environmental data.
9. The well construction system of claim 8 wherein said sensor
package includes a sensor for detecting a hydraulic pressure drop
proximate to said terminal end of said tubing string.
10. The well construction system of claim 8 further comprising a
tension sub adapted to read tension in said tubing string at a
point proximate to said tubing terminal end.
11. A guidance system for conveying a downhole implement,
comprising: a tubing string having a terminal end; a bottom hole
assembly connected to said terminal end of said tubing string, said
bottom hole assembly adapted to convey the downhole implement; a
sensor package mounted proximate to said terminal end of said
tubing string, said sensor package configured to detect
environmental data; a tubing length measurement counter associated
with tubing string; a plurality of sensors on the surface, said
surface sensors configured to detect surface environmental data;
and a surface processor configured to receive said well bore and
surface environmental data, and configured to responsively
determine a corrected tubing length.
12. The guidance system of claim 11 wherein said bottomhole
assembly includes a tractor.
13. The guidance system of claim 12 wherein said tractor is
hydraulically actuated.
14. The guidance system of claim 11 wherein said tubing comprises
composite coiled tubing.
15. The guidance system of claim 14 further comprising data
transmission wire embedded into said composite coiled tubing for
transmitting signals from said sensor package to the surface.
16. The guidance system of claim 15 further comprising electrical
power transmission wire embedded into said composite coiled
tubing.
17. The system of claim 11 further comprising a casing sensor
adapted to provide a indication of distance traversed in a cased
portion of a borehole; and wherein said surface processor is
further configured to calibrate said sub-surface tubing length with
the distance indications provided by said casing sensor.
18. The system of claim 11 wherein said environmental data is
selected from a group consisting of temperature, hydraulic
pressure, hydraulic flow, tubing compression and tubing
tension.
19. A method of determining the true length of composite coiled
tubing inserted into a bore hole, the method comprising: storing
the material properties of the composite coiled tubing, the bore
hole geometry, and the tubing geometry in a memory module of a
computer; recording a surface-measured length of the tubing prior
to insertion; storing the surface-measured length of the tubing in
a memory module of a computer; sensing the temperatures, pressures,
and forces acting on the tubing; storing the temperature, pressure
and force data in a memory module of a computer; calculating a
first length correction using the stored material properties of the
composite coiled tubing, the bore hole geometry, and the
temperature data; calculating a second length correction using the
stored material properties of the composite coiled tubing, the bore
hole geometry, and the pressure data; calculating a third length
correction using the stored material properties of the composite
coiled tubing, the bore hole geometry, and the force data;
determining the length of the tubing using the first, second, and
third length correction.
20. The method of claim 19 wherein the material properties of the
composite coiled tubing of said storing step include the Modulus of
Elasticity and Poisson's ratio.
21. The method of claim 20 wherein the Modulus of Elasticity and
Poisson's ratio are stored in a look-up table, the look-up table
organizing the Modulus of Elasticity and Poisson's ratio with
respect to temperature.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is related to pending application Ser. No.
09/081,961, filed May 20, 1998 and entitled "Well System," which is
hereby incorporated by reference. Further, this application claims
the benefit of provisional application Serial No. 60/269,280 filed
Feb. 16, 2001 and entitled "Length Correction System and Methods,"
which is also hereby incorporated by reference.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The present invention relates to a system for determining
the drilled distance between the surface and a point in a well
bore. More particularly, the present invention relates to a system
using a processor that calculates true measured depth based on data
received from surface sensors, downhole sensors, and in another
aspect, the present invention relates to a method for using a
tubular umbilical to determine the drilled distance between the
surface and a point in a well bore. More particularly, the present
invention provides a method for correcting a surface-measured
length of a tubular umbilical to determine the sub-surface length
of the tubular umbilical by using an environmental profile to
calculate length corrections. Still more particularly, the present
invention relates to methods using temperature differentials,
pressure differentials and axial loadings to correct a
surface-measured length of a composite coiled tubing umbilical to
determine the corresponding sub-surface length of the
umbilical.
[0005] 2. Background of the Invention
[0006] Successful hydrocarbon recovery operations are often founded
on the ability to accurately log the trajectory of a drilled well
bore extending hundreds or even thousands of feet below the surface
of the earth. Accurate depth measurements can play an important, if
not pivotal, role in such hydrocarbon recovery operations.
Referring now to FIG. 1, "measured depth" (MD) is defined as a
drilled distance between a surface point P.sub.0 and consecutive
points P.sub.1, P.sub.2 . . . P.sub.n. In contrast, true vertical
depth (TVD) is the distance between a point P and the surface point
P.sub.0 as measured on a vertical plane. Both MD and TVD are
important for proper log data correlation. Because MD provides a
basis for reference points along a drilled well bore, formation
properties are often linked to accurate MD logs. With
measurement-while-drilling (MWD) instrumentation, formation data
such as gamma emissions and resistivity may be surveyed while a
well bore is drilled. By logging the MD in conjunction with MWD
surveys, formation data can be given a physical location with
respect to the well bore trajectory. Once a well bore has been
completed, a log for the well bore would show the formation
properties at each MD. Such formation data can be used to determine
which layers of formation are likely to hold hydrocarbon deposits.
For example, it may be that the well log indicates that a gas layer
exists at point P.sub.i-1, an oil layer exists at point P.sub.1 (a
"pay zone"), and a water layer exists at point P.sub.i+1. Because
oil is far more profitable to recover than gas, well owners often
wish to drain the oil layer without disturbing the gas deposits
above the oil. This is even more the case with water layers because
recovery of water is rarely, if ever, profitable. Moreover, it is
usually very undesirable to inadvertently drain a gas or water
layer because these fluids tend to flood a well to such a degree
that a well remains nonfunctional until all the water or gas has
been evacuated from the well. Further compounding the inherent
difficulties in this situation is that, in many instances, a pay
zone may be less than fifty feet in a well bore that may be
thousands of feet in length. Therefore, it is important that well
owners obtain well logs having accurate measured depths for
subterranean formations in order to drain a pay zone without
disturbing adjacent layers.
[0007] Further, regulatory authorities often require that owners of
wells keep detailed formation survey information. Inaccurate data
could lead to unintended violations of regulatory rules and subject
the well owner to fines or other penalties. Therefore, accurate MD
logs provide the well owner with the information needed to comply
with the rules governing drilling activities.
[0008] 0 btaining accurate MD logs is usually a fairly
straightforward process for wells using drill string made up of
conventional steel pipe or steel coiled tubing. For conventional
steel pipe, the individual joints making up the pipe string are of
a known length. Thus, an operator needs only keep count of the
number of joints making up the pipe string. For example, referring
to FIG. 1, if one hundred joints, each thirty feet in length, span
between point P.sub.0 and point P.sub.1, then the MD at point
P.sub.1 is 3000 feet. Similarly, when steel coiled tubing 20 is
used, the length of steel coiled tubing 20 payed out from a reel 22
on the surface represents the MD. Often, the length of steel coiled
tubing is measured as a function of the number of revolutions made
by a friction wheel (not shown); coiled tubing length may be also
measured by other commercially available line payout devices. For
example, referring to FIG. 1, a dial (not shown) on reel 22 may
indicate that 3000 feet of steel coiled tubing 20 was payed out
between points P.sub.0 and P.sub.1. Thus, the dial indicates a MD
of 3000 feet at point P.sub.1. In either of the above instances, as
long as the surface measurements are taken properly, the MD should
also be accurate. It should be understood that the examples
discussed are merely illustrative and to not represent expected
depth values or measurement accuracy.
[0009] While these prior art MD survey techniques may be reliable
for tubing formed of metals such as steel, however, such techniques
do not give accurate logs for tubulars made of materials such as
composites. Composite materials for coiled tubing are discussed in
pending application Ser. No. 09/081,961, filed May 20, 1998 and
entitled "Well System," which is hereby incorporated by reference.
Tubulars made of non-metals, such as composites, are susceptible to
significant length changes due to factors such as temperature,
pressure and axial loadings. Unfortunately, elevated temperatures,
high operating pressures and complex compression and tension
loadings are almost always present in a well bore environment.
Thus, a length of composite coiled tubing on the surface may expand
or contract as it enters a well bore. For example, a
surface-measured length at reel 22 may indicate that 3000 feet of
composite coiled tubing was payed out at point P.sub.i. However,
the composite coiled tubing umbilical may have expanded to 3050
feet due to well bore conditions. Accordingly, the actual drilled
depth at point P.sub.i would be 3050 feet, not 3000 feet. An
uncorrected MD log can present serious problems in later operations
when equipment such as perforation charges are tripped downhole to
initiate the drainage of a pay zone at P.sub.i. Since this
equipment is run in on a wireline or other device that is not
subject to the same type or degree of expansion, the charge would
be set at 3000 feet instead of 3050 feet, and possibly within the
gas layer at P.sub.1-1. Indeed, even during successive composite
coiled tubing trips for the same operation, downhole conditions can
vary to a point where it may be difficult to correlate logs of
these successive trips. Despite the critical need for accurate MD
logs, the prior art does not disclose systems or methods that
correct surface measurements of tubulars made of materials that
deform when exposed to environmental factors.
BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS
[0010] The present invention features a system and method for
determining a sub-surface length of tubulars made of materials that
deform when exposed to environmental factors. The sub-surface
length of the tubing generally represents the measured depth. For a
well having a composite coiled tubing umbilical extending from the
surface to a bottom hole assembly in a well bore, an embodiment of
a preferred system includes a surface processor, surface sensors,
downhole sensors and a telemetry system. The surface processor
includes software that determines an environmental profile for the
tubing using the environmental data retrieved by the downhole and
surface sensors. By applying the environmental profile to the
surface-measured length of the tubing umbilical, the computer
software calculates the sub-surface length of the tubing
umbilical.
[0011] An embodiment of the software includes a memory module, a
monitoring module, and a calculating module. Calculated values, as
well as data relating to tubing properties, well trajectory and
other constant values, are stored in the memory module. The
monitoring module receives temperature, pressure and tension
information, and well surveys from downhole and surface sensors via
the telemetry system. The calculating module determines the
sub-surface tubing umbilical length by retrieving the relevant
information from the memory module and monitoring module. A
preferred calculating module determines tubing umbilical length
changes due to temperature differentials, hydraulic pressure
differentials, and axial loadings on the tubing umbilical.
[0012] Another embodiment of the present invention includes logging
while-drilling (LWD) package operated in conjunction with the
preferred system. The LWD package logs formation properties such as
gamma radiation and resistivity. A preferred system couples the
logged formation data information to the calculated sub-surface
tubing length. In still another embodiment, the present invention
is deployed in conjunction with a casing collar or joint locator
device that provides an accurate length measurement of distance
traveled in a cased portion of a well bore. The measurements of the
casing collar joint locator or similar device are used to verify or
calibrate the calculations of the present invention.
[0013] Thus, the present invention comprises a combination of
features and advantages that enable it to overcome various problems
of prior devices. The various characteristics described above, as
well as other features, will be readily apparent to those skilled
in the art upon reading the following detailed description of the
preferred embodiments of the invention, and by referring to the
accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] For a more detailed description of the preferred embodiment
of the present invention, reference will now be made to the
accompanying drawings, wherein:
[0015] FIG. 1 is a schematic drawing showing a well having a
deviated bore through a subterranean formation;
[0016] FIG. 2 is a schematic drawing showing a depth measurement
system constructed in accordance with a preferred embodiment of the
present invention;
[0017] FIG. 3 is a block diagram representing a preferred length
correction method used in conjunction with a depth measurement
system constructed in accordance with a preferred embodiment of the
present invention;
[0018] FIG. 4 is a block diagram representing a preferred routine
for converting a surface-measured length to a reference length as
used in conjunction with the preferred length correction
method;
[0019] FIG. 5 is a cross-sectional view of an exemplary section of
tubing transporting drilling fluid; and
[0020] FIG. 6 is an enlarged side view of an exemplary section of
tubing under axial loading.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0021] The preferred embodiments comprise a system and method for
obtaining an accurate measured depth (MD) by correcting a measured
length of a tubular conduit disposed in a well. According to a
preferred embodiment of the present invention, the MD is
established by correcting a surface measurement of the length of a
tubular member such as composite coiled tubing by accounting for
axial deformation due to an environmental profile of the well. The
term "environmental profile" generally refers to the various
ambient well conditions and loadings imposed by well equipment
along the trajectory of a well bore. These conditions and loadings
are inherent in subterranean well operations. "Tubing" as used
hereinafter refers to any tubular member that is susceptible to
length changes when subjected to environmental factors. Moreover,
the terms "tubing," "coiled tubing" and "umbilical" are used
interchangeably. Referring now to FIG. 2, a bottom hole assembly
(BHA) 30 is shown in a drilled well bore 32. A composite coiled
tubing umbilical 34 extends from reel 36 to BHA 30. As BHA 30
progresses through well bore 32, MD readings are taken to determine
the location of BHA 30. A first depth at which a MD is taken is
designated as depth D.sub.1, a second point at which a MD reading
is taken is designated as depth D2, etc. During drilling, the
approximate physical location of BHA at any time is designated as
depth D.sub.n. Thus, depth D.sub.n represents a current location of
BHA 30, whereas depths D.sub.1 through D.sub.n-1 represent previous
locations of BHA 30.
[0022] In order to better describe the utility of the preferred
embodiments, a depth point is designated as depth D.sub.i. Depth
D.sub.1 represents any point between depth D.sub.1 and depth
D.sub.n along a well bore trajectory. The surface-measured length
of tubing umbilical 34 payed out at depth D.sub.1 is designated as
L.sub.1. Length L, is usually determined by a friction wheel (not
shown) that spins when engaging coiled tubing that is being
injected downhole. However, the surface-measured length L.sub.i may
not be the true drilled depth at depth D.sub.i. The environmental
profile of the well may have caused tubing umbilical 34 to elongate
or shrink. Thus, the sub-surface length of tubing umbilical 34 is
the surface-measured length L.sub.1 plus the amount of shrinkage or
elongation.
[0023] Referring still to FIG. 2, a preferred system 26 for
correcting the measured depth to reflect the actual drilled depth
includes a computer 40, surface sensors generally designated as
numeral 42, downhole sensors generally designated as numeral 44,
and a downhole telemetry system (not shown). The sensors discussed
herein are well known in the industry. Accordingly, the sensors
will be discussed only briefly and are shown schematically in FIG.
2. Preferably, surface sensors 42 include a flowmeter and a
pressure transducer at a drilling mud pump (not shown), a
temperature sensor, a tension meter at tubing injector 38, a length
payout sensor such as a friction wheel (not shown) at reel 36 and a
viscometer. Downhole sensors 44 proximate to BHA 30 preferably
include a pressure transducer, a temperature sensor, a tension sub,
an inclination sensor and an azimuth sensor.
[0024] Computer 40 comprises a memory module (not shown) and a
calculating module (not shown). The memory module includes a survey
file (not shown). The survey file is preferably structured to store
data such as the temperature, the azimuth and the inclination of
the well bore at a particular depth D.sub.1. Thus, an exemplary
entry in a survey file may include a depth (D), an azimuth value
(azi), an inclination value (inc), and a temperature (Te). The
survey file is preferably organized to store data at periodic depth
intervals (e.g., every twenty feet).
[0025] Computer 40 receives data through manual entry or by
communication links to downhole and surface sensors. Downhole
telemetry system (not shown) communicates readings from downhole
sensors 44 to computer 40. Surface measured parameters such as pump
flowrate, pump pressure, mud density ("mud weight") and surface
temperature may be manually read and entered into computer 40.
Alternatively, computer 40 may be directly linked to surface
sensors measuring these parameters. Other parameters such as
drilling mud density, well bore geometry and tubing geometry are
preferably entered manually into computer 40. Preferably,
measurements relating to open hole diameter are entered
automatically. In either instance, computer 40 writes the acquired
data to the memory module.
[0026] Referring now to FIGS. 2 and 3, to find a measured depth
(MD) at depth D.sub.1, the calculating module of computer 40
includes a preferred correction method 100 that accounts for length
changes due to one or more of the following factors: thermal
expansion, differential pressure, hydraulic flow and
tension/compression (i.e., axial loadings). Method 100 uses a first
routine 110 for calculating a reference length RL.sub.j and a
second routine 120 for determining correction length to determine
MD. Reference length RL.sub.j, a theoretical "base line" length
discussed below, is preferably calculated at predetermined time
intervals (e.g., every 30 seconds). Depth D.sub.1, which is a
specific location along the well bore trajectory, is preferably
calculated at pre-determined distances (e.g., every twenty
feet).
[0027] Reference length RL.sub.j provides a pre-determined and
arbitrary reference point from which measured depth calculations
can be made. Coiled tubing at the surface, prior to injection, is
already exposed to factors such as ambient temperature (e.g., the
temperatures of air and drilling fluid) and the hydraulic pressure
of drilling fluid. The coiled tubing can also be exposed to axial
forces (tension) induced by a number of elements including the
operation of the injector, stripper, and tractor and tubing and BHA
weight. These environmental factors will often change during well
servicing operations and lengthen or shorten the tubing introduced
into the well bore. Thus, two sections of coiled tubing, while
having the same length when exposed to the same environmental
profile, will cause a depth wheel to indicate different
surface-measured lengths L if there are differences in the
environmental factors when these two coiled tubing sections are
injected into the well bore. Routine 110 minimizes the errors
caused by variation in surface environmental factors by converting
all the surface-measured lengths L to theoretical reference lengths
RL.
[0028] Referring now to FIG. 4, there is shown a preferred routine
110 for converting a surface-measured length L.sub.j into an
associated reference length RL. Reference length RL.sub.j
represents the calculated length of a given coiled tubing segment S
at a reference environmental profile (e.g., 72 degrees F., no axial
loadings, no hydraulic pressure induced by drilling fluid). Length
changes .DELTA.L.sub.T, .DELTA.L.sub.P, and .DELTA.L.sub.F, are
calculated at steps 112, 113, and 114, respectively and summed to
obtain CL.sub.j, a corrected length difference, at step 116. These
length changes are attributable to the differences in temperatures,
pressures and axial loads between the surface and reference
environmental profiles. For step 112, T.sub.j may be temperature of
air, drilling fluid or any other heat/cooling source that may
affect the coiled tubing. For step 113, P.sub.j is the total
pressure differential seen by the tubing; i.e, the system pressure
drop below the measuring point. For step 114, F.sub.j represents
the axial force imposed on the coiled tubing as measured by a
surface tension meter. Reference length RL.sub.j is calculated at
step 118 by summing the length difference CL, the reference length
of the previous segment (RL.sub.j-1), and the difference between
the surface-measured lengths of two successive coiled tubing
segments (L.sub.j-L.sub.j-1). The other aspects of the FIG. 3
calculations, such as the material constants (e.g., E) are
discussed in detail below.
[0029] Referring back to FIG. 3, preferred correction method 100
calculates the collective length changes caused by temperature
.DELTA.L.sub.Te, pressure .DELTA.L.sub.P and axial loading
.DELTA.L.sub.F in routine 120. Exemplary summation equations for
changes in length due to temperature, pressure and axial loading
(tension) are shown at blocks 122, 124 and 126, respectively. As
can be appreciated, the exemplary equations use a finite element
analysis to determine length changes of tubing umbilical 34. That
is, tubing umbilical 34 is modeled as constructed of a number of
segments defined by the depth values D.sub.i in the survey file.
Thus, to determine the length of an exemplary segment S.sub.i
between depths D.sub.i and D.sub.i-1, routine 110 references the
survey file depth value entries corresponding to these points
(e.g., D.sub.i and D.sub.i-1). At step 130, these length changes
are added to the reference length RL to determine the measured
depth MD.sub.n, or D.sub.n.
[0030] Referring still to FIG. 3, block 122 illustrates an
exemplary summation for finding the total thermal elongation
.DELTA.L.sub.Te at depth D.sub.n. The summation includes the length
changes due to temperature differentials for segments S.sub.1
through S.sub.n. For exemplary segment S.sub.i, length change
.DELTA.L.sub.Tei is calculated using a temperature at depth D.sub.i
designated as Te.sub.1, the reference environmental profile
temperature Te.sub.0 (e.g., 72.degree. F.), the coefficient of
thermal expansion of the tubing material .alpha., and the length of
segment S.sub.i(D.sub.i-D.sub.i-1).
[0031] The thermal elongation calculations use both real time data
and data stored in the memory module. For segment S.sub.n, downhole
sensors 44 proximate to BHA 30 provide the temperature at depth
D.sub.n. For the remaining segments, temperatures at points P.sub.1
through P.sub.n-1 are stored in the survey file of the memory
module and retrieved during length change calculations.
[0032] Preferred correction method 100 accounts for the fact that
the coefficient of thermal expansion .alpha. for composite
materials changes with temperature. The relationship between a and
temperature is usually provided by the manufacturer of the tubing
material and, in any case, can be determined using empirical data
found experimentally using methods well known in the art.
Preferably, the computer memory module includes a look-up table
that correlates temperature Te to a corresponding coefficient of
thermal expansion .alpha.. It should be noted that block 22 uses a
survey file entry for D.sub.n. The depth for this entry is not
available. Accordingly, this depth may be estimated by reference to
the previous depth reading.
[0033] Referring still to FIG. 3, block 124 illustrates an
exemplary summation for finding the total elongation .DELTA.L.sub.P
at depth D.sub.n due to pressure differentials. Differential
pressure in tubing umbilical 34 induces an axial strain that causes
a change in tubing length. Referring now to FIG. 5, drilling fluid
142 is shown flowing downhole through tubing 34, and flowing uphole
in an annulus 144 defined by tubing umbilical 34 and bore hole wall
146. Typically, pressure P.sub.t in the tubing umbilical 34 is
greater than pressure P.sub.a in annulus 144. Pressure differential
.DELTA.P is the difference between the pressure inside the tubing
umbilical 34 P.sub.t and the pressure in the annulus P.sub.a. A
positive pressure differential .DELTA.P tends to expand tubing
umbilical 34 radially. Radial expansion of tubing umbilical 34
causes a reduction in length in tubing umbilical 34. Procedures for
calculating for length changes caused by pressure differentials in
tubular members are well known in the art. Accordingly, the
calculations described are merely illustrative of the general
considerations in performing such calculations.
[0034] Pressure differential .DELTA.P for segment S.sub.i is
calculated using commercially available hydraulic fluid modeling
applications/software. Referring now to FIGS. 3 and 5, typically,
pressure differential .DELTA.P calculations involve the measured
density of the drilling fluid (known as "mud weight"), the pump
pressure, downhole pressure at BHA, the viscosity of the drilling
fluid, the diameter of well bore 32 (D.sub.w), the outer diameter
of tubing umbilical 34 (D.sub.ot), and the inner diameter of tubing
umbilical 34 (D.sub.ot). It should be noted that D.sub.w may be
either the diameter of well bore 32 or the inside diameter of a
well bore completion tubing (not shown) cemented in well bore 32.
It should also be noted that a liner 155 may be installed inside
tubing umbilical 34. In such instances, D.sub.it would be the inner
diameter of the innermost liner. The calculation for pressure
differential uses fluid mechanics solutions which are well known in
the art. Moreover, software programs performing such calculations
are available from a variety of commercial sources.
[0035] Preferably, a differential pressure sensor (not shown) at
BHA 30 is used to check the accuracy of the pressure differential
calculation. It will be appreciated that the above-described
calculations will produce pressure differential values for each
segment of coiled tubing umbilical 34, including the segment
S.sub.n adjacent to BHA 30. Thus, the pressure drop for segment
S.sub.n may be compared with the BHA differential pressure sensor
reading. If the actual and calculated pressure differential values
are within a prescribed tolerance, then it is likely that the
hydraulic fluid modeling equations reliably predict the fluid flow
within the coiled tubing umbilical 34. If there is considerable
variance between the calculated and measured values, then a
different set of fluid flow modeling equations (e.g., Power law,
Bingham, Herschel-Buckley, Newtonian) may be used to calculate
pressure differentials. Indeed, the calculating model may be
programmed to sequence through a number of hydraulic modeling
programs in order to find the modeling program that provides
calculated pressure differential value for segment S.sub.n that
best approximates the measured pressure differential for segment
S.sub.n.
[0036] Using the calculated pressure differential .DELTA.P, a Hoop
Stress .sigma. corresponding to pressure differential .DELTA.P for
segment S.sub.i using pressure differential .DELTA.P and tubing
geometry can be found: 1 HOOP = ( D it ) P 2 W th
[0037] Typically, this calculation requires the inner diameter of
tubing 34 (D.sub.it) and the wall thickness of tubing W.sub.th.
When a liner is installed inside tubing umbilical 34, D.sub.it
would be the inner diameter of the innermost liner. Thereafter, an
axial strain .epsilon. is calculated using the Hoop Stress .sigma.:
2 lat = - HOOP E
[0038] Axial strain .epsilon. is calculated, in part, by using
coiled tubing properties. It is known that the material properties
of composites can change with temperature. Because temperature in
well bore 34 can vary dramatically, the values for Young's Modulus
and Poisson's Ratio are determined at the relevant ambient
temperature. For example, the computer memory module may include a
look-up table that correlates Young's Modulus and Poisson Ratio to
temperature. With these factors considered, the change in length
due to pressure differential is determined by a summation of the
individual changes in length for segments S.sub.i to S.sub.n.
[0039] Referring now to FIG. 6, there are several factors that
affect the tension in exemplary tubing segment S.sub.i: the mass of
tubing segment S.sub.i; the flow of drilling fluid in tubing
segment S.sub.i; sliding frictional force Fs, skin frictional
forces F.sub.m, F.sub.ann, and the loadings caused by the tractor
or injector. Preferred method 100 calculates the tension caused by
the various factors for the coiled tubing segment closest to the
surface and then calculates changes in the tension for each
successive segment.
[0040] The mass of tubing defined by exemplary segment S.sub.i has
a buoyant weight Wb that induces a change in tension in tubing
umbilical 34. Weight W.sub.b of tubing is calculated for the volume
of tubing segment S.sub.i. Buoyancy must be considered because
tubing umbilical 34 is immersed in drilling fluid. An exemplary
equation for determining the force F.sub.w attributable to W.sub.b
is as follows: 3 Fw = - W b cos ( inc i + inc i - 1 2 ) cos ( inc i
- inc i - 1 2 )
[0041] The values for inc are taken from the survey file entries in
the memory module. It will be appreciated that the above equation
accounts for non-vertical well bores.
[0042] Referring still to FIG. 6, drilling fluid flowing downhole
through tubing umbilical 34 and uphole through annulus induces drag
forces on the surfaces of tubing umbilical 34. The drag caused by
drilling fluid flowing through tubing umbilical 34 tends to induce
a tension in tubing umbilical 34 and is designated as F.sub.bore.
The drag caused by drilling fluid flowing through the annulus tends
to induce a compressive force in tubing umbilical 34 and is
designated as F.sub.ann. Fluid drag forces F.sub.bore and F.sub.ann
can be calculated using known fluid mechanics modeling. Exemplary
calculations for determining drag forces based on pressure
differentials along a given surface and the surface areas on which
the pressure differentials act are as follows: 4 F ann = 4 OD (
HoleOD - OD tubing ) ( P ann ) F bore = 4 ID 2 ( P tubingbore )
[0043] Frictional force F.sub.f resists the sliding motion of
composite coiled tubing umbilical 34. In addition to the normal
component of W.sub.b, the tension applied to the coiled tubing
segment and effect of differential pressure also contribute to the
normal force, or side force (RSF), related to frictional force
F.sub.f. Side force RSF has an inclination component, SFI, and an
azimuth component, SFA. Exemplary calculations are as follows: 5
SFI = W b * sin ( inc ) - 2 ( F i - 1 - 4 ID 2 ( P i ) ) * sin (
inc i + inc i - 1 2 ) - F i - 1 * sin ( inc i + inc i - 1 2 ) SFA =
( 2 * ( F i - 1 - 4 ID 2 ( P i ) ) * sin ( azi i - azi i - 1 2 ) +
F i - 1 * sin ( azi i - azi i - 1 2 ) ) * sin ( inc i ) RSF = SFI 2
+ SFA 2
[0044] As can be seen, SFI accounts for the weight of the coiled
tubing (W.sub.b), the pressure differential (dP) and the change in
tension (.DELTA.F.sub.i-1). SFA accounts for the pressure
differential (dP) and the change in tension (.DELTA.F.sub.i-1).
Frictional force F.sub.f is simply the RSF multiplied by the
coefficient of friction .mu.:
F.sub.fi=tmf*.mu.*RSF
[0045] Because the direction of frictional force F.sub.f depends on
motion of composite coiled tubing, a trip mode factor (tmf) is used
to assign the proper positive or negative value to F.sub.f. If
coiled tubing umbilical 34 is being pulled downhole, then tmf is
assigned a positive value (i.e., +1) to denote that the frictional
force tends to mitigate tension. If coiled tubing umbilical 34 is
being pushed uphole, then tmf is assigned a negative value (i.e.,
-1) to denote that frictional force tends to mitigate
compression.
[0046] The tension values may be used to determine the total change
in tension for coiled tubing segment Si:
F.sub.i=F.sub.i-1+F.sub.w+F.sub.f-F.sub.bore+F.sub.ann,
[0047] The above calculations are performed for each segment
S.sub.i. For the initial set of calculations, the coefficient of
friction .mu. is preferably an assumed value of the coefficient of
friction in the well. After this first iteration is complete, the
calculated tension value for segment Sn (i.e., F.sub.n) the segment
of coiled tubing closest to the BHA, is compared to the tension
value as measured by the tension sub adjacent the BHA. If the
calculated and measured tension values are within an specified
tolerance, then .mu. is considered a reasonable estimate of the
well bore coefficient of friction. If the calculated tension value
is not acceptable, the .mu. is revised and the tension calculations
are repeated for all the coiled tubing segments. This process is
continued until the calculated and measured tension values are
reasonably close.
[0048] Finally, the calculated F.sub.i is then used to calculate
.DELTA.L.sub.F.: 6 L F = 1 A i = 1 n F i * ( D i - D i - 1 ) E
[0049] Thus, during operation, the first routine of the calculating
module of the computer periodically a calculates reference lengths
RL as BHA and connected coiled tubing umbilical 34 traverse a well
bore. When the BHA reaches a predetermined depth interval, the
second routine of the calculating module performs a finite element
model analysis of the coiled tubing umbilical 34 in the well bore.
Using measured and calculated environmental factors, the second
routine calculates the measured depth of the BHA. The calculating
module reports the measured depth and updates the survey file in
the memory module with depth, temperature and well bore orientation
data.
[0050] System 100 may be adapted to receive data either through
manual entry or by direct communication links with surface and
downhole sensors. Surface sensors measuring parameters such as
surface-measured length of tubing, pump flowrate, pump pressure,
hook load and surface temperature may be directly fed into a
computer using known communication means. The viscosity and "mud
weight" of the drilling fluid may be varied to accommodate drilling
operations. While viscosity and "mud weight" may be directly fed
into the computer, such variances are expected to be infrequent and
may be better suited for manual entry. In addition, downhole
sensors measuring tension, temperature and pressure may be linked
to the computer via a telemetry system using wiring embedded in the
walls of the tubing. Parameters such as well bore geometry and
coil-tubing geometry are preferably entered manually into the
computer. It should be understood that no particular sequence is
necessary in the data retrieval or entry process. Nor is there a
particular sequence necessary in the calculations of sub-surface
tubing lengths. To the extent that sensor information is directly
fed into the computer, the computer may include a monitoring module
that retrieves data from the surface and downhole sensors.
[0051] Preferred system 100 may also be deployed with other depth
measurement devices. For example, devices that locate joints or
collars in cased well bores can provide accurate depth
measurements. Casing collar locators and other similar devices are
discussed in pending application Ser. No. 09/286,362 filed on Apr.
5, 1999, which is hereby incorporated by reference for all
purposes. During workover operations, a BHA may traverse a span of
cased well bore before forming a new lateral drainhole or well bore
at a kick-off point. A casing collar locator, or similar device,
may be used to definitively measure the sub-surface length of the
tubing between the surface and the kick-off point. This definitive
length may be compared with a calculated length of the tubing to
calibrate well sensors or modify the calculation methodology.
[0052] In another embodiment, the preferred system and/or method
may be used after a well has been drilled. For example, it may be
determined that hydrocarbon deposits exist at measured depth
D.sub.i. In order to perform operations such as perforation at
measured depth D.sub.i, composite coiled tubing may be tripped
downhole to convey the implements needed to perforate the well bore
at depth i. Composite coiled tubing that is tripped downhole may be
subject to the same well bore conditions and operating parameters
that cause elongation during drilling. Thus, the preferred system
could be employed to correct the surface measured length L in order
to convey implements to depth D.sub.i. In this embodiment, the
preferred system is used as a guidance tool.
[0053] In still another embodiment, the present length correction
system or method may be utilized in a three dimensional (3D)
steering system. Prior to well construction activities, operators
typically conduct numerous geological studies of prospective
subterranean formations. Seismic testing, well logging, and other
reservoir description techniques are used to identify and define
hydrocarbon reservoirs. Such testing may suggest that a 3D well
bore trajectory can maximize exposure of a well bore to a
hydrocarbon deposit and/or intersect two or more hydrocarbon
deposits or layers. To implement a 3D well bore, a 3D well bore
trajectory is first developed based on the information provided by
known reservoir description techniques. The 3D well bore trajectory
is then digitally mapped and inputted into a memory module of a
general purpose computer. During drilling operations, the true
measured depth as provided by the length correction method, in
conjunction with azimuth and inclination readings provided by BHA
sensors, can be compared with the digitally mapped 3D well bore
trajectory. If the BHA orientation and location is not consistent
with the desired 3D well bore trajectory, then corrective action
may be taken.
[0054] Preferred system 100 can also be adapted to provide an
indication of the sliding motion of tubing. As explained earlier,
tractor at BHA 30 tows tubing through well bore. "Lockup" often
occurs when coil-tubing ceases to slide smoothly within well bore.
Typically, coiled tubing begins to buckle in a wave or sinusoidal
fashion. If not remedied, coiled tubing buckles helically, a much
worse condition that may require substantial rework to correct. In
other instances, coiled tubing may hang up on a dogleg or other
restriction in the well bore. One method of obtaining an early
indication of tubing "lockup" involves monitoring the coefficient
of friction .mu. between tubing and well bore. An unexpected or
dramatic change in the coefficient of friction .mu. may alert an
operator of such conditions in the well bore. Thus, by calculating
and logging the coefficient of friction, an operator has a real
time or near real time method of monitoring coiled tubing
integrity. Moreover, an automated safety shutdown may be included
in the event that the coefficient of friction exceeds a
pre-determined value.
[0055] It should be understood that the described equations and
calculations are intended only to be exemplary. These equations,
and accompanying descriptions, are merely intended to illustrate
some considerations in deriving solutions for predicting the
tension in tubular umbilical 34. One of ordinary skill in the art
would readily understand the fluid and solid body mechanics
associated with determining tension calculations. Moreover, one
skilled in the art will appreciate that certain aspects of the
described calculation may involve approximation or extrapolation of
calculated or measured data.
[0056] It will also be understood that the correction method and
system reflect a preferred engineering model of well bore
conditions and drilling parameters. Other modeling methods
utilizing different hydraulics and physics modeling may prove
equally satisfactory. For example, for certain applications, it may
be determined that length changes due to one or more factors such
as temperature are sufficiently minimal as to be negligible.
Moreover, advancements in downhole sensors may replace some
calculated values with actual readings (e.g., readings for pressure
differentials). Accordingly, the claims are not limited to the
described modeling techniques or methodologies.
[0057] While preferred embodiments of this invention have been
shown and described, modifications thereof can be made by one
skilled in the art without departing from the spirit or teaching of
this invention. The embodiments described herein are exemplary only
and are not limiting. Many variations and modifications of the
system and apparatus are possible and are within the scope of the
invention. Accordingly, the scope of protection is not limited to
the embodiments described herein, but is only limited by the claims
which follow, the scope of which shall include all equivalents of
the subject matter of the claims.
* * * * *